The current practice in the oil and gas and petroleum chemical/fuel industry for identifying measuring quantities of oil, water, natural gas and other components being produced by a given well, or group of wells, is to separate the produced components in a separator and to identify and measure the produced components individually. The separators are typically large, expensive, maintenance intensive and typically provide production information only after long intervals during which the components separate under the influence of gravity.
Similarly, when a well is being drilled, drilling fluids (“drilling mud”), which one typically complex mixtures of synthetic and organic compounds which are expensive and proprietary in nature, are regurgitated from the wellbore being drilled. The drilling mud is used to lubricate the cutter head, and also to evacuate “cuttings” and rock chips and the like from the wellbore. Further, the drilling mud seals and stabilizes the circumferential walls of the wellbore to prevent leakage, collapse and the like. The fluids which are regurgitated from the wellbore are typically transferred to a settling pond for the solids to “settle out” and thereafter the fluids are transferred to a separator to identify and measure the individual components which may thereafter be reused in the drilling process.
To address the drawbacks of separators, composition meters have been developed to continuously measure volume fractions of natural gas, water and oil being produced. When such a composition meter is combined with a flow meter, production rates for the various components may also be calculated. Known composition meters use measurement of dielectric constant, in combination with a density measurement, to determine the volume fractions.
For known composition meters to be consistently accurate, all the dielectric constants and all the densities of the individual produced fluid components must be known for every measurement condition (temperature and pressure). Unfortunately, this is nearly impossible to accomplish because all the conditions are continually varying and changing as the well is drilled and as the oil well, or group of oil wells, produce. Accuracy of the measurements is further complicated by several of the lower density hydrocarbon components (for example but not limited to, ethane, propane, butane and pentane) existing in either a liquid state or a gaseous state at pressures between approximately 20 and 250 atmospheres. Further, the produced components are typically at very high temperatures and as a result, produced water boils off into steam within the pipes causing identification and measurements of gaseous components to be particularly difficult because the dielectric constant of steam is very close to the dielectric constants of the lower density hydrocarbon components.
Prior art publications claim it is “impossible” to accurately identify and measure the volume fractions of oil, water, and natural gas without knowing how much of each hydrocarbon constituent is in the liquid or gaseous phase at any given time.
Another important measurement problem in the oil and hydrocarbon production industry is the accurate measurement of water content. Water content directly affects the price paid for the product. Various devices are available to continuously measure water content, and most such devices are capacitance meters which measure the dielectric constant of the oil/water mixture to determine the water content. Unfortunately, such devices, which are known in the industry as “water cut meters” are not continuously accurate because the temperature, density and dielectric constant of the oil/water mixture all change as measurement conditions change, which results in measurement errors.
A further complicating factor in measuring volume fraction constituents of mixtures of produced oil and water and natural gas is the salt content of the mixture. The salt also affects the dielectric constant of the fluid components. Similarly, lubricants within the drilling mud and proprietary lubricating drilling fluids may further affect the dielectric constants of the components which may make accurate identification and measurements difficult.
Our method for identifying and measuring volume fraction constituents of a fluid overcomes various of the drawbacks of known volume fraction constituent identifying and measuring apparatus.